Exploration method and system for detection of hydrocarbons

ABSTRACT

A method for detecting hydrocarbons is described. The method includes performing a remote sensing survey of a survey location to identify a target location. Then, an underwater vehicle (UV) is deployed into a body of water and directed to the target location. The UV collects measurement data within the body of water at the target location, which is then analyzed to determine whether hydrocarbons are present at the target location.

CROSS REFERENCE TO RELATED APPLICATION

This application is the National Stage of International Application No.PCT/US2012/064548, that published as WO 2013/071185, filed 9 Nov. 2012,which claims the benefit of International Application No.PCT/US2012/52542, filed 27 Aug. 2012, which claims priority benefit ofU.S. Provisional Patent Application 61/558,822 filed 11 Nov. 2011entitled METHOD FOR DETERMINING THE PRESENCE AND LOCATION OF ASUBSURFACE HYDROCARBON ACCUMULATION AND THE ORIGIN OF THE ASSOCIATEDHYDROCARBONS, each of which is incorporated herein by reference, in itsentirety, for all purposes. This application also claims the benefit ofU.S. Provisional Patent Application 61/595,394 filed 6 Feb. 2012,entitled A METHOD TO DETERMINE THE LOCATION, SIZE AND IN SITU CONDITIONSIN A HYDROCARBON RESERVOIR WITH ECOLOGY, GEOCHEMISTRY, AND COLLECTIONSOF BIOMARKERS, the entirety of which is incorporated by referenceherein. This application also claims the benefit of U.S. ProvisionalPatent Application 61/616,813 FILED 28 Mar. 2012, entitled METHOD FORDETERMINING THE PRESENCE AND VOLUME OF A SUBSURFACE HYDROCARBONACCUMULATION, the entirety of which is incorporated by reference herein.

FIELD OF THE INVENTION

This invention relates generally to the field of hydrocarbonexploration. Specifically, the invention is a method for detectinghydrocarbons (e.g., oil and/or gas), which may include using remotesensing along with an underwater vehicle (UV) equipped with one or moremeasurement components.

BACKGROUND OF THE INVENTION

This section is intended to introduce various aspects of the art, whichmay be associated with exemplary embodiments of the present disclosure.This discussion is believed to assist in providing a framework tofacilitate a better understanding of particular aspects of the disclosedmethodologies and techniques. Accordingly, it should be understood thatthis section should be read in this light, and not necessarily asadmissions of prior art.

Hydrocarbon reserves are becoming increasingly difficult to locate andaccess, as the demand for energy grows globally. Typically, varioustechnologies are utilized to collect measurement data and then to modelthe location of potential hydrocarbon accumulations. The modeling mayinclude factors, such as (1) the generation and expulsion of liquidand/or gaseous hydrocarbons from a source rock, (2) migration ofhydrocarbons to an accumulation in a reservoir rock, (3) a trap and aseal to prevent significant leakage of hydrocarbons from the reservoir.The collection of these data may be beneficial in modeling potentiallocations for subsurface hydrocarbon accumulations.

At present, reflection seismic is the dominant technology for theidentification of hydrocarbon accumulations. This technique has beensuccessful in identifying structures that may host hydrocarbonaccumulations, and may also be utilized to image the hydrocarbon fluidswithin subsurface accumulations as direct hydrocarbon indicators (DHIs).However, this technology may lack the required fidelity to provideaccurate assessments of the presence and volume of subsurfacehydrocarbon accumulations due to poor imaging of the subsurface,particularly with increasing depth where acoustic impedance contraststhat cause DHIs are greatly diminished or absent. Additionally, it isdifficult to differentiate the presence and types of hydrocarbons fromother fluids in the subsurface by such remote measurements.

Current geophysical, non-seismic hydrocarbon detection technologies,such as potential fields methods like gravity or magnetics or the like,provide coarse geologic subsurface controls by sensing differentphysical properties of rocks, but lack the fidelity to identifyhydrocarbon accumulations. These tools may provide guidance on where ina basin seismic surveys should be conducted, but do not significantlyimprove the ability to confirm the presence of hydrocarbon seeps orsubsurface hydrocarbon accumulations. Other non-seismic hydrocarbondetection technologies may include geological extrapolations ofstructural or stratigraphic trends that lead to prospective hydrocarbonaccumulations, but cannot directly detect these hydrocarbonaccumulations. Other techniques may include monitoring hydrocarbon seeplocations as an indicator of subsurface hydrocarbon accumulations.However, these techniques are limited as well. For example, ssatelliteand airborne imaging of sea surface slicks, and shipborne multibeamimaging followed by targeted drop core sampling, have been the principalexploration tools used to locate potential seafloor seeps ofhydrocarbons as indicators of a working hydrocarbon system inexploration areas. While quite valuable, these technologies havelimitations in fidelity, specificity, coverage, and cost.

As a result, an enhancement to exploration techniques that integratesvarious other techniques is needed. This integration of techniques mayprovide a pre-drill technology that determines the presence and locationof thermogenic hydrocarbon seepages from the seafloor. Further, thismethod may be utilized to locate seafloor hydrocarbon seeps accuratelyand cost-effectively over the basin-to-play scale as a means to enhancebasin assessment and to high-grade areas for exploration.

SUMMARY OF THE INVENTION

In one embodiment, a method for detecting hydrocarbons is described. Themethod includes performing a remote sensing survey of a survey location;analyzing the remote sensing data from the remote sensing survey todetermine a target location; deploying an underwater vehicle (UV) into abody of water; navigating the UV within the body of water to the targetlocation; obtaining measurement data within the body of water at thetarget location; determining whether hydrocarbons are present at thetarget location based on the measurement data.

In one or more embodiments, the method may utilize certain featuresrelated to remote sensing. For example, performing the remote sensingsurvey may include creating satellite imagery of the survey location ornavigating an airborne vehicle to obtain an airborne survey of thesurvey location. Further, the remote sensing survey may includeperforming one or more of ocean acoustic waveguide survey; water columnseismic survey; active acoustic sensing survey; imagery and spectroscopyof slicks and atmospheric gas plumes; passive acoustic sensing survey;magnetic and gravity surveys; optical sensing survey and thermalanomalies detection survey. Also, the performing the remote sensingsurvey may include imaging the survey location via one or more ofmultibeam echosounder and sub-bottom profiler via a marine surfacevessel or underwater vehicle.

In one or more embodiments, the method may include certain directmeasurements. For example, the method may include determining theconcentration of one or more of thermogenic methane, ethane, propane,and butane, other alkanes, aromatics, or non-hydrocarbon gases (e.g.,H2S, N2, CO2) from the measurement data, conducting a drop and pistoncore sampling technique based on the obtained measurement data withinthe body of water at the target location, measuring one or more of a pHconcentration and an oxidation state in the body of water; and/ormeasuring magnetic anomalies via multicomponent magnetometers or gravitywith a gravimeter. Further, the method may include obtaining biologicaland chemical sampling of one or more of fluids, gases, and sediments todetermine depth, type, quality, volume and location of a subsurfacehydrocarbon accumulation from the measurement data and/or measuringmolecular and isotopic signatures of non-hydrocarbon gases andhydrocarbons in the body of water. As another example, the method mayinclude creating one or more of a chemical map and a physical map ofanomalies within the body of water to locate hydrocarbon seep vents.

BRIEF DESCRIPTION OF THE DRAWINGS

The foregoing and other advantages of the present disclosure may becomeapparent upon reviewing the following detailed description and drawingsof non-limiting examples of embodiments.

FIG. 1 is a side elevational view of a seafloor.

FIG. 2 is a flow chart for using remote sensing along with an underwatervehicle(s) to perform hydrocarbon exploration in accordance with anexemplary embodiment of the present techniques.

FIG. 3 is a flow chart for using remote sensing along with underwatervehicle (UV) to perform hydrocarbon exploration in accordance withanother exemplary embodiment of the present techniques.

FIG. 4 is a diagram of an AUV in accordance with an exemplary embodimentof the present techniques.

FIG. 5 is a block diagram of a computer system that may be used toperform any of the methods disclosed herein.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

In the following detailed description section, the specific embodimentsof the present disclosure are described in connection with preferredembodiments. However, to the extent that the following description isspecific to a particular embodiment or a particular use of the presentdisclosure, this is intended to be for exemplary purposes only andsimply provides a description of the exemplary embodiments. Accordingly,the disclosure is not limited to the specific embodiments describedbelow, but rather, it includes all alternatives, modifications, andequivalents falling within the true spirit and scope of the appendedclaims.

Various terms as used herein are defined below. To the extent a termused in a claim is not defined below, it should be given the broadestdefinition persons in the pertinent art have given that term asreflected in at least one printed publication or issued patent.

To begin, a seep is a natural surface leak of gas and/or oil. Thehydrocarbon (e.g., petroleum) reaches the surface of the Earth's crustalong fractures, faults, unconformities, or bedding planes, or isexposed by surface erosion into porous rock. The presence of an oil orgas seep at the seafloor or sea surface indicates that three basicgeological conditions critical to petroleum exploration have beenfulfilled. First, organic-rich rocks have been deposited and preserved(source presence). Second, the source has been heated and matured (e.g.,source maturity). Third, secondary migration has taken place (e.g.,hydrocarbon migration from the source location). While a surface seep ofthermogenic hydrocarbons does not ensure that material subsurface oiland gas accumulations exist, seeps provide a mechanism to de-riskelements of an exploration play. That is, the seep may be utilized toremove uncertainty from the modeling of the subsurface.

In the present disclosure, an enhancement to exploration techniques thatintegrates various other techniques is described. As hydrocarbonoccurrence data is typically not easily obtained for a regional scaleand not appropriately evaluated in the context of integrated hydrocarbonsystems, the ability to identify and characterize seeps and thermogenichydrocarbons in the water column provides significant enhancements forevaluating and capturing opportunities. As a result, the presenttechniques provide a method to locate seafloor hydrocarbon seepsaccurately and cost-effectively over the play to basin scale (e.g.,1,000's to 100,000's km²) as a means to enhance basin assessment and tohigh-grade areas for exploration. This method overcomes conventionalfailures in frontier hydrocarbon exploration, which are associated withthe inability to fully evaluate, understand, and appropriately risk thehydrocarbon system components.

In one or more embodiments, the method utilizes a combination ofsatellite, airborne, acoustic and seismic techniques along withunderwater sensors to characterize and map hydrocarbons in a marineenvironment. The combination of geophysical techniques along withunderwater sensors provides a more complete characterization and mappingof hydrocarbons in the marine environment over play to basin scaleexploration areas. The various independent technologies may includeremote sensing (e.g., satellite and/or airborne), seismic and acousticimaging (e.g., ship-based initially: multibeam echosounder, side-scansonar, sub-bottom profiler; which may also be included in AUV forunsurpassed imaging due to proximity to seafloor, but much more local inscope), magnetic and gravity surveying (either from ship or air-basedtools, or from AUV more locally), chemical sensing (AUV: primarily massspectrometer and fluorometer), and sediment, biological and chemicalsampling (e.g., piston cores typically, but may preferably utilize anunderwater vehicle to obtain sediment, fluid (oil, water), or and/or gassamples for noble gases and isotopologues, and biology). The method mayutilize airborne vehicles and marine vessels (e.g., ships and/orunderwater vehicles (e.g., unmanned underwater vehicles, which mayinclude remotely operated vehicles (ROVs) or autonomous underwatervehicles (AUVs)). When combined into an integrated method, thesetechnologies may determine the presence and location of thermogenichydrocarbon seepages from the seafloor to be determined.

To begin, remote sensing techniques may be utilized to determine thelocation of hydrocarbon seeps. Satellite and/or airborne sensingtechniques are used to indicate hydrocarbon slicks that have emanated tothe sea-surface from natural hydrocarbon seeps at the seafloor, thusindicating a favorable area to conduct further surveys using additionaldescribed methods. Seismic reflection imaging is used widely offshore toimage sub-bottom structure and may be utilized for the determination ofpore fluids in the subsurface, such as gas, oil, or water. These surveysare performed in marine vessels. Reflection seismic imaging of seeps inthe water column, especially near the seafloor, due to small bulkdensity and temperature changes in the seep may also be possible, assuggested by references in oceanography (Holbrook W S, Paramo P, PearseS, and Schmitt R W. 2003. Thermohaline fine structure in anoceanographic front from seismic reflection profiling, Science, v. 301,p. 821-824.). Existing 2D and 3D seismic streamer data may contain suchinformation, but this has not been practiced. Seismic responses mayinclude sub-horizontal perturbations in various natural internal oceanstructures, such as thermocline boundaries. Internal noises at shallowdepths and less structuring at large depths may confine detectibleperturbations to specific ranges, such as 400 meters to 2000 metersbeneath the sea surface. Regional 2D seismic data may provide evidenceof such seeps, which may include useful information for evaluatinghydrocarbon exploration opportunities. At lower frequencies, acousticbackscatter techniques using survey swaths of 10-100 km, being used inmarine fishery studies, may be able to quickly locate macroscopic seepsover basin-scale areas greater than 100,000 km² by using the oceanthermocline as a waveguide (Makris N C, Ratilal P, Symonds D T,Jagannathan S, Lee S, Nero R W. 2006. Fish Population and BehaviorRevealed by Instantaneous Continental Shelf-Scale Imaging. Science,311:660-663). However, the efficacy for near-bottom plumes where onlysmall bubbles may be indicative of a hydrocarbon seep is being tested.Such surveys of this kind, either stand-alone or in conjunction withother surveys at the sea surface, may be an effective basin evaluationtool.

A useful technique for imaging potential hydrocarbon seeps includes acombination of ship-based multibeam echosounder (MBES) and sub-bottomprofiler (SBP). The optimum frequencies utilized in these methods isdependent on the water depth expected over the survey area. The MBES isused to obtain sea-bottom topography, roughness, and hardness, while theSBP provides subsurface information to shallow depths beneath theseafloor. Reflective surfaces at the seafloor (e.g., carbonatehardgrounds) can be associated with current microbial activity wherehydrocarbons are metabolized, consistent with hydrocarbon seepage.Similarly, topographic features at the seafloor, such as pockmarks,faults, volcanoes, and salt-related depressions or positive features,locate potentially good areas for hydrocarbon migration from thesubsurface to the seafloor as seeps. MBES data can also indicate densitycontrasts in the water column caused by bubbles emanating from theseafloor as positive indicators of potential hydrocarbon seeps. All ofthis information is integrated with any seismic data described above toprovide targets for additional surveying to confirm the presence ofhydrocarbons.

As another surveying technique, magnetic and gravity surveying may alsobe utilized to obtain additional information for the process.Hydrocarbon seeps can change the pH and oxidation state in thesubsurface within and near the plume, and thus can form magneticminerals, such as magnetite (Fe₃O₄) or greigite (Fe₃S₄) if sufficient Feis present and other conditions are favorable. Weak magnetic anomaliescan be formed by this process, but may be difficult to measure at thesea surface except in very shallow water. Subsea multicomponentmagnetometers may be utilized in AUVs if they have the necessarysensitivity and accuracy. Broad surveys may be performed via airbornevehicles and surface marine vessels to detect geologic perturbationswhere subsurface hydrocarbon migration pathways may be more likely tooccur, or may include collecting data in a near-seafloor environment todetect mineral formation or alteration caused by hydrocarbon seeps andmicrobial interactions (e.g., common microbial mats with distinctivecolors) through surveying with a suitable vehicle, such as an AUV.

After potential seep locations have been indicated through the acousticand seismic tools described, another surveying technique may includechemical sensing. The detection of thermogenic hydrocarbons emanatingfrom seafloor seeps, either at macro- or micro-scale may be detected toconfirm whether hydrocarbon seeps are present at these locations.Measuring concentrations of thermogenic methane, ethane, propane,butane, etc., near the seafloor can be performed via compacthigh-sensitivity mass spectrometers and laser fluorometers (for aromaticcompounds generally associated with hydrocarbon liquids), which may beutilized on an underwater vehicle, such as an AUV.

As another surveying technique, an underwater vehicle may also beutilized to collect further data from a seep. The underwater vehicle mayinclude an unmanned underwater vehicle (e.g., an AUV, remotely operatedvehicle (ROV)), a manned underwater vehicle and/or one or more sensorsthat are towed behind a marine vessel. The underwater vehicles mayinclude one or more sensors configured to detect chemical or physicalanomalies that are indicative of hydrocarbon seeps.

Additionally, these sensors within an underwater vehicle, which may bean unmanned vehicle, can be used to map chemical or physical anomaliesaround a seep to locate the specific seep vent or discharge location.The seep vent location provides a favorable site for additionalbiological and chemical sampling of fluids, gases, and sediments tofurther enhance the analysis. In particular, this method may includedetermining the presence and estimating information, such as depth,type, quality, volume and location, about a subsurface hydrocarbonaccumulation from the measured data from the underwater vehicle. Inparticular, the present techniques involve the use of three independenttechnologies: clumped isotope geochemistry, noble gas geochemistry, andmicrobiology, which are combined and integrated as a workflow to enhancehydrocarbon exploration success. These three methods may provideinformation about the depth, fluid type (oil vs. gas) and quality, andvolume of subsurface hydrocarbon accumulations to be determined from thesampling and analysis of hydrocarbon seeps (e.g., offshore and/oronshore). That is, the method may integrate existing and new biologicaland geochemical indicators to provide insights in opportunityidentification. In addition, the integration of these biological andgeochemical indicators with geological/geophysical contextual knowledgeshould further provide enhancements to hydrocarbon opportunityidentification. These other techniques are described in U.S. Patent No.61/595,394; U.S. Patent No. 61/616,813; U.S. Patent No. 61/558,822,which are each incorporated herein in its entirety.

In one embodiment, the present techniques involve one or more ofmicrobial genomics; noble gas geochemistry and clumped isotopegeochemistry of hydrocarbon phases. These techniques may be utilized todetermine and/or estimate the presence and information, such as volume,depth, type, quality, and location of the subsurface hydrocarbonaccumulation.

The microbial genomics may be utilized to provide information on themetabolic processes of subsurface microbial communities linked withthose microbes sampled within sea-bottom seeps. This microbial genomicsinformation provides an indication as to the presence of a subsurfaceaccumulation and provides an estimation of its location (e.g., depth)based on biologic temperature ranges. This aspect relies upon thetransport microbes from deep to shallow habitats to a hydrocarbon seepfrom subsurface hydrocarbon accumulations. This process may explain, forexample, the presence of “displaced” thermophiles (microbes that live inhigh temperature environments) in arctic environments where crude oil ispotentially degraded by anaerobic microbes, thus supporting a connectionto a deeper hydrocarbon/sediment source. Different areas of hydrocarbonseepage may have different microbial anomalies relative to normal marineconditions, depending on subsurface reservoir conditions. Anunderstanding of the metabolic processes of subsurface microbialcommunities linked with those microbes sampled within seabottom seepsshould allow the presence of a subsurface accumulation to be detectedand allow an estimation of its location (depth) based on biologictemperature ranges.

As an example, one embodiment may include a method of identifying ahydrocarbon system. In this method, a sample from an area of interest isobtained. Then, a first plurality of analyses is used to determine acommunity structure of an ecology of the sample and a second pluralityof analyses is used to determine a community function of the ecology ofthe sample. The community structure and the community function are usedto determine whether the ecology of the sample matches a characteristicecology of a hydrocarbon system. When the ecology of the sample matchesthe characteristic ecology, the sample is identified as part of thehydrocarbon system. This aspect is further described in U.S. Patent No.61/595,394, which is incorporated herein in its entirety.

With regard to the noble gas geochemistry, the noble gases (He, Ne, Ar,Kr, Xe) are conservative elements that do not generally participate inchemical reactions. The concentrations of noble gases in oil, gas, andwater are based on the combined influence of their solubilities, whichare a function of pressure, temperature, and fluid composition (P-T-X)that prevailed during dissolution or exsolution, interaction and mixingwith other fluids, and the ingrowth of noble gases from the radioactivedecay of crustal minerals. If the water PTX conditions in contact with asubsurface hydrocarbon accumulation can be estimated or measured, thehydrocarbon accumulation size can be estimated or calculated based onthe solubility partitioning of noble gases between water andhydrocarbons. An atmospherically uncontaminated hydrocarbon seep sampleanalyzed for noble gases along with estimated water PTX conditions,should allow an accumulation size (hydrocarbon/water ratio) to beestimated.

As an example, one embodiment may include a method for determining thepresence, type, quality and/or volume of a subsurface hydrocarbonaccumulation from a sample related thereto. An initial concentration ofatmospheric noble gases present in formation water in contact with thesubsurface hydrocarbon accumulation is measured or modeled. The modeledinitial concentration is modified by accounting for ingrowth ofradiogenic noble gases during residence time of the formation water. Asample related to the subsurface hydrocarbon accumulation is obtained.Concentrations and isotopic ratios of noble gases present in the sampleare measured. The measured concentrations and isotopic ratios of theatmospheric noble gases and the radiogenic noble gases present in thesample are compared to the measured/modified modeled concentrations ofthe formation water for a plurality of exchange processes. A source ofhydrocarbons present in the sample is determined. An atmospheric noblegas signature measured in the hydrocarbon phase is compared with themeasured/modified modeled concentration of the atmospheric noble gasesin the formation water for the plurality of exchange processes. At leastone of a type of hydrocarbons in the subsurface accumulation, a qualityof hydrocarbons in the subsurface accumulation, a hydrocarbon/watervolume ratio in the subsurface accumulation prior to escape to thesurface, and a volume of the subsurface accumulation is determined.

In another aspect, a method is disclosed for determining a presence,type, quality and volume of a subsurface hydrocarbon accumulation basedon analysis of a sample related thereto. The sample is analyzed todetermine a geochemical signature of the sample. An initialconcentration of atmospheric noble gases present in formation water incontact with the subsurface hydrocarbon accumulation is determinedIngrowth of radiogenic noble gases is modeled to modify the initialconcentration for given formation water residence times. A residencetime of the formation water is determined. An extent of interaction witha hydrocarbon phase is determined. The origin of the sample isdetermined. At least one of a type, quality and hydrocarbon/water volumeratio when the origin of the sample is a hydrocarbon accumulation isdetermined. From the hydrocarbon/water volume ratio, the volume of thehydrocarbon accumulation is determined.

In another aspect, a method is disclosed for determining a presence,type, quality and volume of a subsurface hydrocarbon accumulation from ahydrocarbon sample thereof. An initial concentration of atmosphericnoble gases present alongside a hydrocarbon species is determined Arange of expected concentrations of atmospheric and radiogenic noblegases present in the sample is modeled for a range of residence timesand for various extents of interaction between formation water and ahydrocarbon phase. Concentrations and isotopic ratios of noble gasespresent in the sample are measured. The measured noble gasconcentrations are compared with the modeled range of expectedconcentrations of atmospheric and radiogenic noble gases. Using thecomparison it is determined whether the hydrocarbons present in thesample have escaped from the subsurface accumulation. From the measurednoble gas concentrations and the modeled range of expectedconcentrations of atmospheric and radiogenic noble gases, the type andquality of hydrocarbons in the subsurface accumulation and thehydrocarbon/formation water volume ratio of the subsurface accumulationare estimated. The estimated type and quality of hydrocarbons in thesubsurface accumulation and the hydrocarbon/formation water volume ratioof the subsurface accumulation are integrated with seismic reflectionconstraints on a volume of the hydrocarbon accumulation and a volume ofwater present in the hydrocarbon accumulation, thereby determining thevolume of hydrocarbons present in the subsurface accumulation.

In still another aspect, a system is disclosed for determining apresence, type, quality and volume of a subsurface hydrocarbonaccumulation from a hydrocarbon sample thereof. The system includes aprocessor and a tangible, machine-readable storage medium that storesmachine-readable instructions for execution by the processor. Themachine-readable instructions include code for determining expectedconcentrations of noble gases present in formation waters, code formodeling one or more exchange and fractionation processes in theexpected concentrations of noble gases present in the sample, code formeasuring concentrations of noble gases present in the sample, code forcomparing the measured concentrations of noble gases with the modeledconcentrations of noble gases in the formation waters, code fordetermining, using said comparison, the type and quality of hydrocarbonspresent in the subsurface, and code for determining whether hydrocarbonspresent in the sample originate directly from a source rock or whetherthe hydrocarbons present in the sample have escaped from a subsurfaceaccumulation.

In still another aspect, a computer program product having computerexecutable logic recorded on a tangible, machine readable medium, thecomputer program product comprising: code for determining expectedconcentrations of noble gases present in formation waters, code formodeling one or more exchange and fractionation processes in theexpected concentrations of noble gases present in a hydrocarbon sampletaken from a hydrocarbon seep, code for measuring concentrations ofnoble gases present in the hydrocarbon sample, code for comparing themeasured concentrations of noble gases with the modeled concentrationsof noble gases in the formation waters, code for determining, using saidcomparison, a type and a quality of hydrocarbons present in thehydrocarbon sample, and code for determining whether hydrocarbonspresent in the hydrocarbon sample originate directly from a source rockor whether the hydrocarbons present in the sample have escaped from asubsurface accumulation.

In yet another aspect, a method of producing hydrocarbons, comprising:determining a presence, type, quality and/or volume of a subsurfacehydrocarbon accumulation from a hydrocarbon sample thereof, wherein thedetermining includes modeling an initial concentration of atmosphericnoble gases present in formation water in contact with a subsurfacehydrocarbon accumulation, modifying the modeled initial concentration byaccounting for ingrowth of radiogenic noble gases during residence timeof the formation water, obtaining a hydrocarbon sample, measuringconcentrations and isotopic ratios of atmospheric, mantle derived andradiogenic noble gases present in the hydrocarbon sample, comparing themeasured concentrations and isotopic ratios of the atmospheric noblegases and the radiogenic noble gases present in the hydrocarbon sampleto the modified modeled concentrations of the formation water for aplurality of exchange processes, determining a source of hydrocarbonspresent in the hydrocarbon sample, comparing an atmospheric noble gassignature measured in the hydrocarbon phase with the modified modeledconcentration of the atmospheric noble gases in the formation water fora plurality of exchange processes, determining at least one of a type ofhydrocarbons in the subsurface accumulation, a quality of hydrocarbonsin the subsurface accumulation, a hydrocarbon/water volume ratio in thesubsurface accumulation prior to escape to the surface, and a volume ofthe subsurface accumulation; and producing hydrocarbons using at leastone of the determined type, quality, volume ratio, and volume of thesubsurface accumulation. This aspect is further described in U.S. PatentNo. 61/616,813, which is incorporated herein in its entirety.

A hydrocarbon compound contains atoms of carbon and hydrogen, and willbe present as a natural stable isotope of carbon (12C, 13C) or hydrogen(1H, or 2H often termed deuterium or D). 12C forms 98.93% of the carbonon Earth, while 13C forms the remaining 1.07%. Similarly, the isotopicabundance of 1H on earth is 99.985% while 2H has an abundance of 0.015%.Isotopologues are compounds with the same chemical formula, but differin their molecular mass based on which isotopes are present in themolecule (e.g. 13C1H3D or 12C1H4). Clumped isotopes are isotopologues inwhich two or more rare isotopes are present in close proximity (i.e.,isotopic ‘clumps’), and for which the molecular ordering of isotopes isas important as their total abundance. These rare species havedistinctive thermodynamic stabilities and rates of reaction withspecific fractionations during diffusion and mixing, and are far morediverse than the singly-substituted species that are the focus ofestablished branches of isotope geochemistry. Common volatilehydrocarbons have large numbers of stable isotopologues (e.g., methanehas 10; ethane has 21; propane has 36). Measurements of a single gasspecies could, in principle, yield two or more mutually independentthermometers that could indicate the “residence” temperature ofhydrocarbons within a subsurface accumulation, in effect determining thedepth location of a potential exploration target from a seep sample.

As an example, one embodiment may include a method of determining apresence and location of a subsurface hydrocarbon accumulation from asample of naturally occurring substance. According to the method, anexpected concentration of isotopologues of a hydrocarbon species isdetermined. An expected temperature dependence of isotopologues presentin the sample is modeled using high-level ab initio calculations. Asignature of the isotopologues present in the sample is measured. Thesignature is compared with the expected concentration of isotopologues.Using the comparison, it is determined whether hydrocarbons present inthe sample originate directly from a source rock or whether thehydrocarbons present in the sample have escaped from a subsurfaceaccumulation. The current equilibrium storage temperature of thehydrocarbon species in the subsurface accumulation prior to escape tothe surface is determined A location of the subsurface accumulation isdetermined.

Also according to disclosed methodologies and techniques, a method ofdetermining a presence and location of a subsurface hydrocarbonaccumulation is provided. According to the method, a hydrocarbon sampleis obtained from a seep. The hydrocarbon sample is analyzed to determineits geochemical signature. The analyzing includes measuring adistribution of isotopologues for a hydrocarbon species present in thehydrocarbon sample. A stochastic distribution of the isotopologues forthe hydrocarbon species is determined A deviation of the measureddistribution of isotopologues from the stochastic distribution of theisotopologues for the hydrocarbon species is determined. The origin ofthe hydrocarbon sample is determined. A storage temperature of thehydrocarbon species is determined when the origin of the hydrocarbonsample is a hydrocarbon accumulation. From the storage temperature, thelocation of the hydrocarbon accumulation is determined.

According to methodologies and techniques disclosed herein, a method isprovided for determining a presence of a subsurface hydrocarbonaccumulation from a sample of naturally occurring substance. Accordingto the method, an expected concentration of isotopologues of ahydrocarbon species is determined. An expected temperature dependence ofisotopologues present in the sample is modeled using high-level abinitio calculations. A clumped isotopic signature of the isotopologuespresent in the sample is measured. The clumped isotopic signature iscompared with the expected concentration of isotopologues. It isdetermined, using the comparison, whether the hydrocarbons present inthe sample have escaped from a subsurface accumulation, therebydetermining a presence of the subsurface accumulation.

According to disclosed methodologies and techniques, A computer systemis provided that is configured to determine a presence and location of asubsurface hydrocarbon accumulation from a sample of naturally occurringsubstance. The computer system includes a processor and a tangible,machine-readable storage medium that stores machine-readableinstructions for execution by the processor. The machine-readableinstructions include: code for determining an expected concentration ofisotopologues of a hydrocarbon species; code for modeling, usinghigh-level ab initio calculations, an expected temperature dependence ofisotopologues present in the sample; code for measuring a clumpedisotopic signature of the isotopologues present in the sample; code forcomparing the clumped isotopic signature with the expected concentrationof isotopologues; and code for determining, using said comparison,whether hydrocarbons present in the sample originate directly from asource rock or whether the hydrocarbons present in the sample haveescaped from a subsurface accumulation.

According to still more disclosed methodologies and techniques, a methodof determining a presence and location of a subsurface hydrocarbonaccumulation and the origin of associated hydrocarbons collected from asurface seep is provided. According to the method, molecular modeling isintegrated to determine the expected concentration of isotopologues froma hydrocarbon species of interest. A concentration of the isotopologuesof the hydrocarbon species of interest is measured. Statisticalregression analysis is conducted to converge on a temperature-dependentequilibrium constant and an isotopic signature unique to the absoluteconcentrations measured for multiple co-existing isotopologues. For thehydrocarbons collected from the surface seep, at least one of storagetemperature, a source facies, and thermal maturity of source rockassociated therewith is determined. This aspect is further described inU.S. Patent No. 61/558,822, which is incorporated herein in itsentirety.

Beneficially, this integrated method provides a pre-drill technologythat may determine the presence and location of thermogenic hydrocarbonseepages from the seafloor. Further, this method may be utilized tolocate seafloor hydrocarbon seeps accurately and cost-effectively overthe basin-to-play scale as a means to enhance basin assessment and tohigh-grade areas for exploration. The analysis of seismic and acousticdata from surface surveys, plus integrated interpretation of geophysicaland chemical data from underwater vehicles, provides an enhanced methodto locate seafloor seeps of thermogenic hydrocarbons cost-effectivelyover large areas. Further, this process provides the ability to detectthe presence, volume, depth, and fluid type/quality of subsurfacehydrocarbon accumulations, which is useful in hydrocarbon (HC) resourceexploration in frontier and play extension settings. As a result, thisprocess provides geoscientists with an enhanced identification techniquefor hydrocarbon accumulations, while having a greater confidence in theidentified hydrocarbon accumulations. Various aspects of the presenttechniques are described further in FIGS. 1 to 5.

FIG. 1 is a diagram illustrating the numerous subsurface sources andmigration pathways of hydrocarbons present at or escaping from seeps onthe ocean floor 100. Hydrocarbons 102 generated at source rock (notshown) migrate upward through faults and fractures 104. The migratinghydrocarbons may be trapped in reservoir rock and form a hydrocarbonaccumulation, such as a gas 106, oil and gas 108, or a gas hydrateaccumulation 110. Hydrocarbons seeping from the gas hydrate accumulationmay dissolve into methane and higher hydrocarbons (e.g., ethane,propane) in the ocean 112 as shown at 114, or may remain as a gashydrate on the ocean floor 100 as shown at 116. Alternatively, oil orgas from oil/gas reservoir 108 may seep into the ocean, as shown at 118,and form an oil slick 120 on the ocean surface 122. A bacterial mat 124may form at a gas seep location, leaking from gas reservoir 106, and maygenerate biogenic hydrocarbon gases while degrading thermogenic wet gas.Still another process of hydrocarbon seepage is via a mud volcano 126,which can form an oil slick 128 on the ocean surface. Oil slicks 120 and128 or methane (and e.g., ethane, propane, etc.) gas 130 emittedtherefrom are signs of hydrocarbon seepage that are, in turn, signs ofpossible subsurface hydrocarbon accumulation. The signatures measuredfrom each of these seeps may be analyzed according to disclosedmethodologies and techniques herein to discriminate between thedifferent origins of hydrocarbons encountered at these seeps. Inparticular, methodologies and techniques disclosed herein maydiscriminate between hydrocarbons that have migrated directly to thesurface without encountering a trap within which they can be accumulated(e.g., a first source) and hydrocarbons that have leaked from asubsurface accumulation (e.g., a second source). If the presence andvolume of such a hydrocarbon accumulation can be identified, it ispossible the hydrocarbons from such an accumulation can be extracted.

FIG. 2 is a flow chart 200 for using remote sensing along with anunderwater vehicle (UV) to perform hydrocarbon exploration in accordancewith an exemplary embodiment of the present techniques. In this flowchart 200, various blocks relate to performing remote sensing on asurvey location, such as blocks 202 to 206, which may be referred to asa remote sensing stage. Other blocks involve the more directmeasurements, which involve the operation of an underwater vehicle, suchas blocks 208 to 216, which may be referred to as a direct sensingstage. Finally, block 218 relates to the use of the measured data forhydrocarbon discovery, which may be referred to as a discovery stage.

The remote sensing stage is described in blocks 202 to 206. At block202, a regional survey location is determined. In the explorationprocess, offshore regions or large areas that may have hydrocarbonpotential are sometimes offered or awarded by various governments tocompanies for exploration purposes. Within these regions that mayinclude sizes exceeding 100,000 km², it is useful for companies toquickly and cost-effectively determine whether the region has thepotential to yield hydrocarbon accumulations (i.e., evidence within theregion for an active hydrocarbon system) and, if so, to locate and focuson areas within the region that have the best exploration potential.Once the regional survey location is identified, remote sensing may beperformed in the identified survey location, as shown in block 204. Theremote sensing survey may include satellite imagery and airborne surveysalong with water column surveys, as well. The remote sensing techniquesmay include the ocean acoustic waveguide; water column seismic; activeacoustic sensing (multibeam echo sounder, two dimensional (2D) seismic,three dimensional (3D) seismic, sub-bottom profiler, side scan sonar,etc.); imagery and spectroscopy of slicks and atmospheric gas plumes(e.g., infrared (IR) to detect atmospheric gases, radar reflectivity,etc.); towed chemical sensors (mass spectrometer, etc.); passiveacoustic sensing; discrete sampling from surface vessel of air, water,or soil at various locations; drop and piston cores; magnetic andgravity surveys; optical sensing; thermal anomalies detection; and/orany other remote sensing technique. These remote sensing techniques maybe performed via satellites, airborne vessels, and/or marine vessels.Concurrently with collection of the remote sensing data or after theremote sensing measurement data is collected, the measured data from theremote sensing techniques may be analyzed to determine targetedlocations, as shown in block 206. An example may include interpretingmultibeam echosounder and sub-bottom profiler data acquired via a marinevessel. The multibeam backscatter data may be examined for anomaloussea-bottom hardness, roughness, and/or volumetric heterogeneity in theshallow sub-bottom and by examining the bathymetry data collected forlocal highs, lows, fault lines, and other geologic indicators that maybe consistent with permeable pathways for hydrocarbon migration to theseafloor. In other words, these remote sensing methods provide targetsfor possible hydrocarbon seep locations. Similarly, if any slick datafrom previous satellite imagery interpretations are available or seismicdata, etc. are available, that information may be integrated with themultibeam and sub-bottom profiler data to improve or “high-grade” thebest locations for possible hydrocarbon seeps. Additionally,interpretations made from these results, preferable with theavailability of seismic information, may allow geologic interpretationsor models to be constructed about possible hydrocarbon “plays” orprospects, based on this initial information. These potential areas mayagain be useful targets to determine whether thermogenic hydrocarbonsare present as seeps.

The direct measurements in the direct sensing stage, which involve theoperation of an underwater vehicle, are described further in blocks 208to 216. At block 208, the underwater vehicle is deployed at the targetlocation. The deployment may include transporting the underwater vehicleto the target location, which may be one of various target locationsidentified from the remote sensing survey. The underwater vehicle may betransported via another marine vessel and/or airborne vessel to thedesired target location. The deployment may also include configuring theunderwater vehicle to obtain certain measurements and/or to follow acertain search pattern. As may be appreciated, the configuration of theunderwater vehicle may be performed prior to the transporting of theunderwater vehicle to the target location, at least partially during thetransporting of the underwater vehicle and/or at least partially at thetarget location. Regardless, the configuration of the underwater vehiclemay include determining a sequence of operations to be performed by theunderwater vehicle to perform the direct measurement survey at thetarget location. For instance, this configuring the underwater vehiclemay include programming the navigation components to follow a generalpath, adjusting operational parameters and/or settings, adjusting theconfiguration of the monitoring components, and/or other suitableoperational adjustments. This may also include inserting certainequipment (e.g., certain monitoring components) into the underwatervehicle for use in monitoring. Once configured, the underwater vehiclemay be deployed into the body of water, which may include launching theunderwater vehicle, and initiating underwater vehicle measurementoperations. As an example, the deployment may include lowering theunderwater vehicle from the deck of a marine vessel into the body ofwater or dropping the underwater vehicle into the body of water. Theinitiation of the measuring may be performed on the vessel or once theunderwater vehicle is disposed in the body of water.

The operation of the underwater vehicle is described in blocks 210. Asmay be appreciated, the operation of the underwater vehicle, which maybe an AUV, may include various processes that repeat during anoperational period (e.g., period of time that the underwater vehicle ismeasuring data). During this operational period, the underwater vehiclemay navigate toward targeted locations or may obtain measurements alonga specific search pattern. To navigate, the underwater vehicle mayutilize navigation components, which may include one or more propulsioncomponents, one or more steering components and the like. The one ormore propulsion components may include a motor coupled to one or morebatteries and coupled to a propeller assembly, via a shaft, for example,as is known in the art. The propeller assembly may be utilized to movefluid in a manner to move the underwater vehicle relative to the body ofwater. The navigation components may utilize sensors or other monitoringdevices to obtain navigation data. The navigation data may includedifferent types of navigational information, such as inertial motionunit (IMU), global positioning system information, compass information,depth sensor information, obstacle detection information, SONARinformation, propeller speed information, seafloor map information,and/or other information associated with the navigation of theunderwater vehicle.

The underwater vehicle may obtain measurements within the targetlocation. For example, the underwater vehicle may utilize themeasurement components, such as one or more modules to receivemeasurement data and a process control unit to manage the received data,calculate operational and measurement parameters from the received data,determine adjustments to the operation of the underwater vehicle anddetermine if additional measurement information should be obtained. Themeasurement components may include fluorescence polarization components,fluorometric components, wireless component (e.g., acoustic componentsand/or SONAR components), methane or other chemical compound detectioncomponents, temperature components, camera components and/or othermeasurement components. The measurement data may include camera images,SONAR data and/or images, acoustic data, temperature data, massspectrometric data, conductivity data, fluorometric data, and/orpolarization data, for example. The data can be in the format of images,raw data with specific format for the component, text files, and/or anycombination of the different types. The underwater vehicle may includeintegrated sensor payloads that are utilized to monitor a large area,while two or more AUVs, which may communicate between each other, mayalso be utilized in other applications to monitor other areas that maybe smaller in extent. Other sensors may include functionality to providechemical specificity of applied sensors (e.g., underwater massspectrometry). These sensors may discriminate thermogenic hydrocarbons,which may be preferred, from biogenic hydrocarbons and may determinewhether the seep is associated with gas, oil, or a combination of gasand oil. As an example, the underwater vehicle may be an AUV. The AUVmay include artificial intelligence that is configured to detect andnavigate toward peak concentrations of targeted chemicals, such aspropane, and data reporting is done periodically to a small surfacevessel or to shore using satellite links.

Once the measurement data is obtained, it may be analyzed to determinewhether hydrocarbons are present and their location, as shown in block212. As the measurement data may include various forms, the measurementdata may be analyzed on the underwater vehicle via the respectivemeasurement equipment and/or transmitted to another location forprocessing. Certain of these aspects are discussed below.

At block 214, the sediment, biological and chemical samples may beobtained and analyzed to further enhance the process. Sediment samplesmay be acquired by ship-based drop or piston core surveys, based on theintegration of the remote sensing and direct measurement information(e.g., sub-bottom profile and seismic data linked to seep locations),which may greatly improve the ability to collect meaningful sedimentsamples that contain hydrocarbons. These samples are then analyzed(which may be in a laboratory or onboard a vehicle) using fluorometry,gas chromatography (GC), and more sophisticated GC-MS (massspectrometry)-MS or GC-GC time of flight mass spectrometry or additionaltechniques to obtain biomarkers and other indicators of hydrocarbonsource facies and thermal maturity. The samples may also be obtained viaunderwater vehicle. In particular, this method may include determiningthe presence and estimating information, such as depth, type, quality,volume and location, about a subsurface hydrocarbon accumulation fromthe measured data from the samples acquired by the underwater vehicle.The samples may be subjected to three independent analysis technologies,such as clumped isotope geochemistry, noble gas geochemistry, andmicrobiology. These may each be utilized to provide additionalinformation about the depth, fluid type (oil vs. gas) and quality, andvolume of subsurface hydrocarbon accumulations. That is, the method mayintegrate existing and new biological and geochemical indicators toprovide insights in opportunity identification. In addition, theintegration of these biological and geochemical indicators withgeological/geophysical contextual knowledge with the other geologicaland measurement data further provides enhancements to hydrocarbonopportunity identification. These analysis techniques are described inU.S. Patent No. 61/595,394; U.S. Patent No. 61/616,813; and U.S. PatentNo. 61/558,822.

The remote sensing measurement data may be integrated with the directsensing data to enhance a subsurface model, as shown in block 216. As anexample, the measured data may be organized with the location of theunderwater vehicle or a location to correlate the measured data withother surveys of the subsurface geology. As a specific example,multi-beam echo sounding data may be associated with the location of asurface vehicle and used to detect sea bottom topography, texture, anddensity, and SBP (sub-bottom profiler) to locate shallow subsurface gasanomalies and hydrate layers associated with bottom simulatingreflectors. The measured data from chemical sensors associated with anunderwater vehicle may be used to locate anomalous chemistriesassociated with seeps and seep vents, to map these anomalies relative togeologic features, and to distinguish thermogenic from biogenic gas, andgas from oil. These different types of data may be integrated based onlocation information associated with the respective data to provideadditional information. Chemical results from drop or piston coresurveys are further integrated with seismic, gravity, and magnetic datathat have been combined to create subsurface models of the geology andhydrocarbon system in a region. The subsurface models are furtherenhanced by the results of microbial ecology, clumped isotopes, andnoble gas signatures from samples acquired by an underwater vehicle.

Finally, block 218 relates to the designation of a drilling location fordiscovery of hydrocarbons based on the measured data. The discovery ofhydrocarbons is based on a determination that is made whether to accesshydrocarbons from the target locations based at least partially on themeasured data or the integrated data. The determination may includeanalyzing the measured data for one or more of the hydrocarbonaccumulation type, quality, depth and volume obtained from the microbialecology, clumped isotope and noble gas signatures and/or these dataintegrated with the geological and geophysical data. The discovery ofthe hydrocarbons involves drilling a well to provide access to thehydrocarbon accumulation. Further, the production may include installinga production facility is configured to monitor and produce hydrocarbonsfrom the production intervals that provide access to the subsurfaceformation. The production facility may include one or more units toprocess and manage the flow of production fluids, such as hydrocarbonsand/or water, from the formation. To access the production intervals,the production facility may be coupled to a tree and various controlvalves via a control umbilical, production tubing for passing fluidsfrom the tree to the production facility, control tubing for hydraulicor electrical devices, and a control cable for communicating with otherdevices within the wellbore.

Beneficially, this integrated method provides an enhancement in theexploration of hydrocarbons. In particular, the method may be utilizedprior to drilling operations to reduce exploration risk by providingmore information about the presence and location of thermogenichydrocarbon seepages from the seafloor. As a result, this methodprovides a cost-effective technique to enhance basin assessment and tohigh-grade areas for exploration. The analysis of seismic, gravity,magnetics, and acoustic data from surface surveys, plus integratedinterpretation of physical and chemical data from underwater vehicles,provides an enhanced method to locate seafloor seeps of thermogenichydrocarbons cost-effectively over large areas.

Further, mapping of anomalies around hydrocarbon seeps may be useful tolocate areas where fluids are exiting the subsurface onto the seafloor.This approach may be utilized to enhance other technologies, such asdrop core sampling of hydrocarbon-associated sediments, or theacquisition of fluids or gases above, at, or under the seafloor.Accordingly, this integrated method may be utilized to further enhancethe exploration activities.

As another specific embodiment, FIG. 3 is a flow chart 300 for usingremote sensing along with an underwater vehicle (UV) to performhydrocarbon exploration in accordance with another exemplary embodimentof the present techniques. In this flow chart 300, various blocks relateto the remote sensing stage, direct sensing stage and discovery stage,as noted above in FIG. 2, and are utilized to determine the location ofa hydrocarbon seep. In this flow chart 300, the remote sensing stage mayinclude blocks 302 to 310, the direct sensing stage may include blocks312 to 318 and the discovery stage may include blocks 320 to 322.

The remote sensing stage is described in blocks 302 to 310. At block302, imagery and spectroscopy of slicks and atmospheric gas plumes isperformed. For example, these tools may include high resolutionsatellite, radar (e.g., synthetic aperature radar) and ultra-violetimagers that can detect the presence and geographic extent of oilslicks. Multi-spectral imaging data can also be used to map largeoil-slicks that occur offshore. As another example, infrared sensing maybe utilized to detect atmospheric gases, radar reflectivity; and/orairborne surveys. Then, at block 304, a regional survey location may beutilized to identify one or more target location within the region. Thisdetermination may include identifying a region that has potential toinclude one or more hydrocarbon seeps based on the imagery andspectroscopy data.

Once the regional survey location is identified, the remote sensing maybe performed via a marine vessel, as shown in block 306, and via theunderwater vehicle, as shown in block 308. At block 306, remote sensingdata is obtained from a surface marine vehicle, such as a surfacevessel. The remote sensing data from the surface vessel may includeperforming active acoustic sensing (e.g., multibeam echo sounder, 2Dseismic, 3D seismic, sub-bottom profiler, side scan sonar, etc.),chemical analysis (e.g., towing in situ chemical sensors (massspectrometer, etc.)); discrete in situ sampling from surface vessel ofair, water, or soil at various locations; drop or piston cores, samplingsystem; pumping liquid to sensing location, passive acoustic techniques;magnetic and gravity surveys; optical sensing (remote or in situ);thermal anomalies analysis; any other remote or in situ sensingtechnique. At block 308, the remote sensing data from the underwatervehicle (e.g., underwater deployment device (AUV, ROV, floats, any otherunderwater deployment device); may include analyzing of sediment orwater samples. Then, at block 310, the specific locations for sediment,biological and chemical sampling (e.g., target location) are determinedto further enhance the analysis. This determination may includeidentifying target locations for focused investigations of points ofinterest to confirm presence of thermogenic hydrocarbon seepage (e.g.,molecular geochemistry of seafloor sediments, water column, etc.).

The biological and chemical sampling in the direct sensing stage isperformed at blocks 312 to 318. The sample is obtained in block 312. Thelocation of the hydrocarbon sample may be based on a known seep locationor determining a seep location through known techniques. The one or moresamples are obtained from the hydrocarbon sample location. If thehydrocarbon location is a seep, the sampling of seep locations mayinclude (i) confirming the presence of hydrocarbons (e.g., biogenic,thermogenic, abiogenic) at the seep location and (ii) conductingadvanced biological and geochemical analysis after appropriate sampling.The sampling methods used to collect the samples of interest may includegravity or piston drop core sampling, the use of manned submersibles,autonomous underwater vehicles (AUV) or remotely operated vehicles (ROV)with coring sampling devices, and gas sampling apparatus. Sampling mayalso include collection of surface sediments surrounding the seeplocation and collection of fluids from within the seep conduit. A samplecan comprise (i) any surface sample, such as a sediment sample takenfrom the sea-floor or a sample of seeped fluids, (ii) any sample takenfrom the water column above a seep location, m or (iii) any sample takenfrom within the seep conduits below the surface. Identification of thepresence of hydrocarbons may be determined by standard geochemicalanalysis. This may include but is not restricted to maximum fluorescenceintensity and standard molecular geochemistry techniques such as gaschromatography (GC). For biology samples, appropriate preservationshould be taken, as is known in the art. Similarly, gas and/or oilsamples that are subjected to clumped isotope and noble gas analysis maybe collected using funnels or inserted into seep conduits connected tosampling cylinders.

After the sample obtaining stage, the molecular and isotopic signaturesof non-hydrocarbon gases and hydrocarbons in the sample are measured, asshown in block 314. In particular, the molecular and isotopic signaturesof non-hydrocarbon gases (e.g. H₂S, CO₂, N₂) and hydrocarbons aremeasured, which includes the analysis of noble gas signatures (He, Ne,Ar, Kr and Xe) and the isotopologue or clumped isotope signature of bothnon-hydrocarbon and hydrocarbon molecules (in gases, water, and/oroils). Isotopologues are molecules that differ only in their isotopiccomposition. Clumped isotopes are isotopologues that contain two or morerare isotopes. The sample of interest may comprise water, oil, naturalgas, sediments or other types of rocks, or fluids present in sediments,rocks, water or air. Measurement of the abundance of each noble gasisotope can be conducted following standard extraction techniques usingmass spectrometry. Measurement of the abundance of each clumped isotopeor isotopologue can be conducted using multiple techniques, such as massspectrometry and/or laser-based spectroscopy. The ecology of samples(e.g., sediment, seawater, seeped fluids and the like) can becharacterized through a number of different techniques. These mayinclude but are not restricted to deoxyribonucleic acid (DNA) analysis,ribonucleic acid (RNA) analysis, (meta) genomics, (meta) proteomics,(meta) transcriptomics, lipid analysis, and culture-based methods. Theanalysis may include both (semi) quantitative (e.g., qPCR (quantitativepolymerase chain reaction), next-generation sequencing) and qualitativeassessments (e.g., sequencing, microscopy, phenotype tests). Standardmolecular analysis is conducted to characterize the organic signature ofhydrocarbons extracted from the sample. Analysis may include the use ofgas chromatography-mass spectrometry (GC/MS), GC/GC/MS, and liquidchromatography. Inorganic analysis of samples may also be conducted.Analysis may include but is not restricted to inductively coupled plasmamass spectrometry (ICP-MS) and ICP-optical emission spectroscopy. Gaschemistry analysis may also be conducted and may include isotoperatio-mass spectrometry and GC.

At block 316, the interpretation of advanced molecular and isotopicsignatures, including noble gas signatures and clumped isotopesignatures of hydrocarbon and non-hydrocarbon molecules is performed.This interpretation involves determining the type and quality ofhydrocarbons and/or depth of a hydrocarbon accumulation and/or volume ofa hydrocarbon accumulation. As an example, the noble gases may beutilized to determine hydrocarbon accumulation volume, hydrocarbon typeand oil quality and is provided in a U.S. Patent No. 61/616,813. Asnatural gases and oils are initially devoid of noble gases, the additionof these through interaction with formation water provides informationabout the samples. The impact of this interaction on isotopic ratios andabsolute concentrations of noble gases present in the hydrocarbon phaseis a function of three variables: (i) the initial concentration andisotopic signature of noble gases in the water phase, (ii) thesolubility of noble gases in water and oil (solubility of noble gases inoil is controlled by oil quality), and (iii) the ratio of the volumes ofoil/water, gas/water or gas/oil/water.

The initial concentration of noble gases in the water phase prior tointeraction with any hydrocarbons can be accurately measured orestimated. Noble gases dissolve in water during recharge from meteoricwaters or at the air/water boundary for seawater. This initial signatureis therefore dominated by atmospheric noble gases, namely 20Ne, 36Ar,84Kr and 132Xe. The amount of noble gases that dissolve into the waterphase obeys Henry's Law, which states that the amount of noble gasesdissolved in water is proportional to the partial pressure of the noblegases in the atmosphere (which varies as a function of altitude formeteoric water recharge). The Henry's constant is directly related tothe salinity of the water phase and the ambient temperature during thetransfer of noble gases to the water. Formation waters recharged frommeteoric waters at the air/soil interface may have an additionalcomponent of atmospheric derived noble gases from that which is expectedpurely from equilibrium, “excess air”. These influences may be subjectto adjustments (e.g., correction schemes, such as those noted inAeschbach-Hertig, W., Peeters, F., Beyerle, U., Kipfer, R.Palaeotemperature reconstruction from noble gases in ground water takinginto account equilibrium with entrapped air. Nature, 405, 1040-1044,2000, for example). The resulting noble gas signature therefore liesbetween air-saturated water (ASW), air-saturated seawater (ASS) andair-saturated brine (ASB) for any given temperature. Radiogenic noblegases are then introduced following recharge through radioactive decayof minerals within the subsurface. The concentration of the radiogenicnoble gases typically increases with increasing formation waterresidence time (or age). This evolving noble gas signature in the waterphase is changed as a result of mixing and interaction with otherfluids. The solubilities of noble gases in water have been determinedfor a range of different temperatures, as is known in the art (e.g.,Crovetto, R., Fernandez-Prini, R., Japas, M. L. Solubilities of inertgases and methane in H2O and D2O in the temperature range of 300 to600K, Journal of Chemical Physics 76(2), 1077-1086, 1982; Smith, S. P.Noble gas solubilities in water at high temperature. EOS Transactions ofthe American Geophysical Union, 66, 397, 1985.). Similarly, the measuredsolubility of noble gases in oil increases with decreasing oil density(Kharaka, Y. K. and Specht, D. K. The solubility of noble gases in crudeoil at 25-100° C. Applied Geochemistry, 3, 137-144, 1988.). The exchangeof atmospheric noble gases between formation water and both the oiland/or gaseous hydrocarbon phase can occur through various processes,and the extent of fractionation induced by each of these processes givesrise to different signatures in the different phases. These processescan be modeled and may comprise equilibrium solubility, Rayleigh stylefractionation and gas stripping. The exchange of noble gases between oiland water may result in the oil phase developing an enrichment in theheavy noble gases (Kr and Xe), and an associated depletion in the lightnoble gases (He and Ne) relative to the water phase. This is because ofthe greater solubility of the heavier noble gases in oil than in water.In contrast, the interaction of a gas phase with water may result in thegas phase becoming relatively enriched in the lighter noble gases anddepleted in the heavy noble gases relative to a water phase. Themagnitude of this fractionation may change depending upon the exchangeprocess involved and on the density of the oil phase

Assuming that a subsurface signature is preserved during migration tothe surface, the phases that interacted (e.g. oil-water, gas-water orgas-oil-water) with a seeped hydrocarbon by measuring the concentrationof noble gases in the hydrocarbon sample may be determined. The noblegases provide a conservative tracer of the hydrocarbon type presentwithin the subsurface (oil vs. gas). Knowledge of the solubility ofnoble gases as a function of oil density provide further informationabout the estimate of the oil quality when the hydrocarbon present isdetermined to be oil. Finally, given that two of the three variablesthat control the exchange of noble gases between water and hydrocarbonsare known or can be modeled, the hydrocarbon/water volume ratio within asubsurface hydrocarbon accumulation can be determined. From this it ispossible to quantitatively predict the volume of hydrocarbon presentwithin a subsurface accumulation.

In addition to the utilization of noble gases to determine hydrocarbonaccumulation volume, hydrocarbon type and oil quality, the clumpedisotope geochemistry may be utilized to determine the depth of ahydrocarbon accumulation. As an example, U.S. Patent No. 61/558,822describes a process for determining the clumped isotope signature of anymolecule. The clumped isotope signature of any molecule is a function of(i) temperature-independent randomly populated processes (e.g.,stochastic distribution) and (ii) thermal equilibrium isotopic exchange.The latter process is controlled or dependent on the surroundingtemperature. The stochastic distribution of any isotopologue can bedetermined from the bulk isotope signatures of the species from which itderives. For example, determining the stochastic distribution ofisotopologues for methane requires knowledge of the 13C and D signaturesof methane. The isotopic signature of hydrocarbon gases that are storedin a subsurface accumulation or that are present at seeps may reflectthe isotopic signature of the gas generated from the source rock. Assuch, this signature may be concomitantly determined during thecharacterization of the hydrocarbons present at a seep and substituteddirectly in to the calculation of the stochastic distribution. There maybe occasions, however, when the isotopic signature of gases is alteredby processes like mixing with biogenic gas. In such instances,correction schemes known in the art may be relied upon, such as Chung etal., (1988; H. M. Chung, J. R. Gormly, R. M. Squires. Origin of gaseoushydrocarbons in subsurface environments: theoretical considerations ofcarbon isotope distribution in M. Schoell (Ed.), Origins of Methane inthe Earth. Chem. Geol., 71 (1988), pp. 97-103 (special issue)). Thecorrection scheme may be used to deconvolve such contributions and reachthe initial primary isotope signature that should be used in thecalculation of the stochastic distribution.

The expected increased abundance, or enrichment, of any givenisotopologue or clumped isotope can be modeled or empirically determinedfor any given temperature. By measuring the clumped isotope andisotopologue signatures of a given molecule, and through knowledge ofthe stochastic distribution, the enrichment of the measuredconcentrations relative to the stochastic distribution can be used todetermine the temperature in the subsurface from which this molecule isderived.

Hydrocarbons that derive from a subsurface accumulation may retain aclumped isotope signature that more reflects the temperature at whichthe hydrocarbons were stored in the subsurface. This non-kinetic controlon the isotopic exchange reactions in isotopologues of hydrocarbons thatoriginate from a subsurface accumulation arises as a result of theinherently long residence times of hydrocarbons in the subsurface.Through application of a suitable geothermal gradient to the storagetemperature derived from the clumped isotope signature, the location(depth) within the subsurface that seep-associated hydrocarbonaccumulations reside may be estimated.

As another independent technique useful for the detection of hydrocarbonaccumulations and their location or depth, the microbial ecology andbiomarker signature of hydrocarbon seeps may be used to determine thedepth of a hydrocarbon accumulation and/or the hydrocarbon accumulationvolume and/or the hydrocarbon type and oil quality, as described in U.S.Patent No. 61/595,394. Ecology is the study of interactions betweenliving organisms and the non-living surrounding environment. Microbialecology refers to the ecology of small organisms like bacteria andarchaea. Ecology includes biotic parameters like community composition(e.g., which organisms are present), community function (e.g., whatthose organisms are doing), organism behavior, organism quantity andmetabolite production. Additionally, ecology includes abiotic parameterslike pH, temperature, pressure and aqueous concentrations of differentchemical species. We may measure all or some of these parameters todescribe the ecology of a hydrocarbon seep. Seeps that are connected tohydrocarbon accumulations may have different ecologies than seeps thatare not connected to hydrocarbon accumulations.

Microbial ecology involves using genomics and culture based techniquesto describe the community composition. (Meta) Genomics, (meta)transcriptomics, (meta) proteomics and lipid measurements can becombined with chemical measurements to determine the community function.Changes in temperature drive changes in community structure andfunction. Changes in hydrocarbon type and volume present in theaccumulation change community structure and function. If a seep isconnected to a hydrocarbon accumulation, these ecological differencesmay be reflected in samples acquired from the seep.

The sediment and fluid samples from in and around a hydrocarbon seep maybe collected and appropriately preserved. Changes in the ecology ofthese samples may reflect the conditions of the subsurface accumulationsfeeding the seeps. Samples from a seep not connected to a hydrocarbonaccumulation may not contain ecological parameters associated with adeep hot hydrocarbon environment.

Then, at block 318, the hydrocarbon accumulation type and quality, depthand volume obtained from the microbial ecology, clumped isotope andnoble gas signatures may be integrated with remote sensing data obtainedfrom remote sensing, as noted in blocks 302 to 310, to confirmaccumulation materiality. This integration step includes incorporationall aspects of the hydrocarbon system model along with geological andgeophysical data, such as basin modeling, and/or probabilistic orstatistical risk assessments. Included in this assessment are the risksof adequate source, maturation, migration, reservoir presence andquality, trap size and adequacy, and seal. If aspects of the riskassessment, including the results of blocks 312 to 318, are sufficientlyfavorable, a decision as to whether to stop or continue the processremains.

The discovery stage includes blocks 320 to 322. At block 320, adetermination to access the hydrocarbons based on the measured data andthe integrated data is made. This determination may include a variety ofeconomic factors that include the associated costs of drilling a wellversus the economic benefits of discovering an accumulation of the sizeexpected at the depth expected incorporating appropriate risks. If thecost benefit is deemed sufficient, then, at block 322, a well is drilledand hydrocarbons are discovered based on the determination. Thisdiscovery of hydrocarbons may be similar to block 218 of FIG. 2.

As noted above, these remote sensing and direct measurements may beperformed by an underwater vehicle and/or a marine vessel. Themeasurements may include detecting seep locations via a high-resolutionmulti-beam survey, as described in Valentine et al. (2010; Valentine DL, Reddy C M, Farwell C, Hill T M, Pizarro O, Yoerger D R, Camilli R,Nelson R K, Peacock E E, Bagby S C, Clarke B A, Roman C N, Soloway M.Asphalt Volcanoes as a Potential Source of Methane to Late PleistoceneCoastal Waters. Nature Geoscience Letters. DOI: 10.1038/NGEO848)) in theSanta Barbara basin. While certain measurements may be performed via asurface vessel, the costs of doing regional surveys with towed tools,especially at depths greater than a few hundred meters, are very highdue to the limited speeds that can be achieved while keeping the devicenear the seabed with manageable tension loads on the support cable. Thetypical spatial resolution achieved with these towed systems is also low(e.g., on the order of hundreds of meters), compared to the approximateten meter spatial resolution obtained by using a mass spectrometer andfluorometer incorporated into an underwater vehicle (e.g., AUV). Thereis also the added complexity and potential source of error that mayoccur if water samples are collected for shipboard analysis and have notmaintained their in situ properties.

To enhance the measurement data, an underwater vehicle may be used toobtain certain data. The underwater vehicle may include an AUV, ROV,towfish or manned submersibles. The different configurations of theseAUVs and method of operation may include various different combinationsof components to provide the measurement data for a specific survey. Thedifferent configurations may be utilized to perform the directmeasurements of the target locations, as noted above. These measurementsmay include analysis of gases or water soluble hydrocarbons dissolved inwater as well as phase-separated pockets of hydrocarbons in the water.In addition, the direct measurements may include information aboutgeological features associated with active hydrocarbon seep locations.These underwater vehicles are known in the art, as noted above withregard to pipeline leak detection. See; e.g., R. Camilli, A. Duryea2007., in Proc. IEEE/MTS OCEANS (IEEE/MTS, Vancouver, Canada, 2007), pp.1-7 (10.1109/OCEANS.2007.4449412).

As an example, underwater vehicles may include various differentchemical sensors. Specifically mass spectrometry and fluorometry may beutilized to conduct surveys to locate hydrocarbons in the marineenvironment. To enhance the hydrocarbon survey techniques, an AUV may beutilized in a system that can be programmed to conduct autonomousmissions to any depth of exploration interest. That is, the system mayobtain measurement data near the seafloor that results in unsurpassedseafloor, sub-bottom, and in situ water chemistry resolution in nearreal time. This real time acquisition may provide additionalclarification as to the location of the hydrocarbons.

In another example, the underwater vehicle may include a methane sensorto detect the presence of hydrocarbons near the seabed. This underwatervehicle may also include gravity and magnetic sensors to performadditional data that may be correlated to the methane sensor data. Toprovide additional enhancements, the measured data may be organized withthe location of the underwater vehicle to correlate the measured datawith other surveys of the subsurface geology. The chemical sensors canbe used to locate anomalous chemistries associated with seeps and seepvents, to map these anomalies relative to geologic features, and todistinguish thermogenic from biogenic gas, and gas from oil. Further,sensors may also be utilized to provide chemical and isotopic analysisof hydrocarbons to determine whether a seep source is thermogenic orbiogenic. Each of these different sensors may be included in theunderwater vehicle to provide enhancements to the measured datacollected and analyzed.

Accordingly, in certain embodiments, underwater vehicles (e.g., unmannedunderwater vehicle) may include sensors capable of detecting chemical orphysical anomalies that are indicative of hydrocarbon seeps andcorrelating them to a specific location. The m chemical specificity ofapplied sensors, particularly underwater mass spectrometry supplementedby a fluorometer, may also provide the discrimination of thermogenicseeps from biogenic seeps and to determine whether the seep isassociated with gas, oil, or gas and oil. The sensors may include a massspectrometer, a methane detector, fluorometer, multibeam echo sounder(MBES), sub-bottom profiler (SBP), side-scan sonar (SSS), and camera[this has been done to some extent in oceanographic research].Regardless, the sensors may be utilized to map the hydrocarbon types andconcentrations, which may be utilized to indicate the presence andsurface-subsurface linkages to a hydrocarbon system. In addition, thesensors may differentiate biogenic hydrocarbons from thermogenichydrocarbons, oil from gas, and provide additional information regardinglocations for drop cores or piston cores, and further sampling.

The underwater vehicle provides an enhancement to the ability to locatehydrocarbon seeps efficiently and in a cost-effective manner for a largeregion. This is accomplished through a combination of directmeasurements with the remote sensing instruments. In this manner, thesubsurface models can be enhanced and reduce exploration risk. Further,this acquisition of this direct measurement data may be performedinexpensively and efficiently at regional scales. As a result, theexploration process may be enhanced to improve the ability to find andprioritize play extensions.

As an example of an AUV, FIG. 4 is a diagram of an AUV in accordancewith an exemplary embodiment of the present techniques. In this AUV 400,a process control unit 402 is utilized to manage the navigationcomponents and the measurement components. The process control unit 402includes a processor 403, memory 404 and sets of instructions (e.g.,master navigation module 410 and master measurement module 420) that arestored in the memory 404 and executable by the process control unit 402.The power for the process control unit 402 may be supplied by one ormore batteries 406. Also, the process control unit 402 may include acommunication component 408, which may include an antenna and otherequipment to manage communications with other systems, such as marinevessel and/or GPS.

The navigation components of the AUV 400 may include the masternavigation module 410, a mapping component, such as SONAR component 412,motion sensor component 416 and propulsion component 418. The masternavigation module may operate by the processor executing the sets ofinstructions configured to: manage the different navigation components,calculate the path of the AUV, obtain signals (e.g., GPS signals and/orwireless guidance signals), communicate with the propulsion systems toadjust steering and/or speed of the AUV, obtain motion sensor data,and/or calculate the AUV's location based on different data (e.g., GPSdata, wireless guidance data, motion sensor data and mapping componentdata). The SONAR component 412 may include SONAR sensor equipment tosend and receive SONAR signals and provide associated SONAR data to themaster navigation module. The SONAR component 412 may also be utilizedfor the detection of hydrocarbons external to the AUV (e.g., in fluiddisposed external to the AUV, such as a body of water that the AUV isdisposed within). The motion sensor component 416 may include varioussensors and other equipment to obtain motion sensor data about theforces applied to the AUV 400 (e.g., currents and fluid flows). Themotion sensor component 416 may include a processor that communicateswith a gyroscope, depth sensor, velocity meter along with various othermeters to measure the orientation or other parameters of the AUV. Also,the propulsion component 418 may include two propeller assembliesenclosed by a propeller support member, a motor coupled to the batteries406.

The measurement components of the AUV 400 may include the mastermeasurement module 420, resistivity components 422 a-422 c, cameracomponent 424 a-424 c and/or other hydrocarbon detection component 426along with the SONAR component 412. The master measurement module mayoperate by the processor executing the sets of instructions configuredto: manage the different measurement components, determine whetherhydrocarbons are present external to the AUV (e.g., in fluid disposedexternal to the AUV, such as a body of water that the AUV is disposedwithin), communicate with the propulsion systems to adjust steeringand/or speed of the AUV if hydrocarbons are detected, obtain measurementdata and the AUV's location based on different hydrocarbon indications,and store certain measurement data and AUV location data. Theresistivity components 422 a-422 c may include various sensor that areconfigured to detect resistivity via contact with the fluid adjacent tothe AUV and provide these measurements to a processor, which isconfigured to send and receive commands, process the resistivity dataand to communicate resistivity data and/or certain notifications withthe master measurement module 420. The camera components 424 a-424 c mayinclude various cameras that are configured to obtain images (e.g., theimages may be subjected to different filters) of fluids, bathymetricfeatures, biologic communities, bubbles, etc. adjacent to the AUV pathand provide these images to a processor, which is configured to send andreceive commands, process the images, and to communicate camera dataand/or certain notifications with the master measurement module 420. Theother hydrocarbon detection components 426 may include various pipingand equipment that is utilized to obtain measurement data near the AUV.The other hydrocarbon detection components may include fluorescencepolarization component, fluorometric component, wireless component(e.g., acoustic component and/or SONAR component 412), methanecomponent, temperature component, mass spectrometer component and/orother suitable measurement components. For example, a temperaturecomponent typically has a thermocouple or a resistance temperaturedevice (RTD). The measurement data may include acoustic images, acousticdata, temperature data, fluorometric data, and/or polarization data, forexample. The other hydrocarbon detection components 426 may also includea processor configured to send and receive commands, to process themeasured data, and to communicate measured data and/or certainnotifications with the master measurement module 420.

The equipment within the AUV 400 may be coupled together throughphysical cables to manage the distribution of power from the batteries406 and to manage communication exchanges between the equipment. As anexample, power distribution is provided between the process control unit402, the one or more batteries 406 and the communication component 408via lines 409, while the communication distribution is provided betweenthe process control unit 402 and the communication component 408 vialine 407. Other communication and power distribution lines are not shownfor simplicity in this diagram. Also, the communication between certaindevices may be via wireless communications, as well. Accordingly, thespecific configuration with the AUV provides flexibility in obtainingdifferent types of data, which may be managed for certain locations.

Multiple different sensors may be preferred to further verify themeasured data from one of the sensors. For example, the presence ofmethane alone does not provide the clear indication of a biogenic gasfrom thermogenic gas and whether wet gas and/or oil are present.Biogenic gas is not generally a conventional exploration target,although it can be exploited in some environments. The formation ofbiogenic gas is related to methanogenic bacteria that in some casesreduce CO₂ and oxidize organic matter to produce only methane in shallowenvironments. As such, it is most common to find small amounts ofmethane (C₁) in shallow marine sediments that are insignificant forexploration purposes, effectively acting as a “contaminant” in theabsence of other hydrocarbon indicators. Conversely, thermogenic gas isgenerated from an organic rich source rock at depth that produces a hostof hydrocarbon gases (C₁-C₅) and heavier liquids (oil). The massspectrometer is capable of analyzing for methane, ethane, propane, andhigher hydrocarbons (up to 200 atomic mass units) that provides adistinction between biogenic and thermogenic gas, gas wetness, andwhether a seep is related primarily to oil, gas, or both a combinationof oil and gas. The fluorometer supplements the mass spectrometer byindicating the presence of aromatic compounds consistent withliquid-rich hydrocarbons.

While the mass spectrometer has the capability of analyzing masses to200 amu, the sensitivity to lower atomic masses (e.g., <70 amu) isgreater. As a result, certain lighter masses (actually mass/charge ratioor m/z) that are generally distinctive for a compound of interest forhydrocarbon exploration may be useful in hydrocarbon exploration. Thesemasses or their ratios relative to a mass that remains generallyconstant in water are utilized. For example, water with mass 17represented by 16O1H+ is commonly chosen for this purpose. There is alsothe added complexity of certain masses not being uniquely distinctivefor a single compound. An example is mass 16, which is both a primarymass indicator for methane (12C₁H₄) and oxygen (16O). To avoidsignificant contributions from interfering compounds, methane ismeasured at mass 15 rather than 16, and commonly compared to mass 17, oramu ratio 15/17 is used to indicate methane amount for a particularmeasurement. This ratio assumes that any fluctuation in the water ionpeak is due to variability in instrument response (e.g., instrumentdrift) because the concentration of water in water is well known. Somecommonly used masses (or ratios relative to mass 17) of importance arelisted below in Table 1.

TABLE 1 Commonly used masses (mass/charge ratio) for locating andcharacterizing hydrocarbon seeps m/z Interpreted Compound Abbreviation 4Helium (He⁺) He 14 Nitrogen (N⁺ and N₂ ⁺⁺) plus some methane and NITethane 15 Methane (or methyl C₁ fragment) (CH₃ ⁺) MTH or C1 17 Water(¹⁶O¹H⁺) H2O 20 Water (H₂ ¹⁸O⁺) 22 Carbon dioxide (CO₂ ⁺⁺) 28 Nitrogen(N₂ ⁺) 30 Ethane (or ethyl C₂ fragment) ETH or C2 (C₂H₆ ⁺); ethanesometimes @27 32 Oxygen (¹⁶O₂ ⁺) O2 34 Hydrogen sulfide (H₂S⁺) andoxygen ¹⁶O¹⁸O H2S 39 Propane (C₃H₈) various fragments PRO 40 Argon (Ar⁺)Ar 41 Propane (or propyl C₃ fragment) (C₃H₇ ⁺); propane C₃ ⁺ sometimesmeasured @39 or 43 if no major interferences (e.g., from CO₂ ⁺ @ 44) 44Carbon dioxide (CO₂ ⁺) CO2 55 Naphthene C₄ fragment (C₄H₇ ⁺) NAP 57Paraffin C₄ fragment (C₄H₉ ⁺) PAR 58 Various “butane” fragments (C₄H₁₀)BUT 60 Acetic acid (CH₃COOH⁺), or from carbonyl sulfide HAC (COS⁺) 78Benzene (C₆H₆ ⁺) BEN 91 Toluene (C₇H₇ ⁺) TOL 97 Alkylated Naphthene(C₇H₁₃ ⁺) ANP 106 Xylene (C₈H₁₀ ⁺) XYL

The mass spectrometer housed within an AUV may provide the rapidmeasurement of masses in the range of 1 amu to 200 amu for a watersample about every five seconds, depending on water depth. The presenceof C₁, C₂, C₃ ⁺, paraffins, naphthenes, and the aromatics benzene andtoluene (sometimes xylene), as well as the non-hydrocarbon gases CO₂,H₂S, N₂, Ar, and He, or their ratios, provides beneficialinterpretations to be made regarding the location and characterizationof hydrocarbon seeps. A biogenic gas consists only of methane(occasionally very small amounts of ethane) and is called a “dry” gas.Thermogenic gas usually has varying amounts of heavier or higherhydrocarbons of C2-C5 and is called a “wet” gas.

TABLE 2 Ratios used to determine whether a source contains dry or wetgas with MS. Dry Gas Wet Gas (C₂/C₁)1000 <8 >8 C₁/(C₂ + C₃) >100 <100

Table 2 shows general guidelines for distinguishing dry gas from wet gaswith mass spectrometric measurements. Dry gas can also be thermogenic,derived from very mature source rocks. The mass spectrometric data mayallow the distinction between a dry biogenic gas, which is characterizedby a greater relative amount of 12C, and a dry thermogenic gascharacterized by a relatively greater amount of 13C. Wet gases may beassociated with oils. Greater amounts of the higher mass compounds, suchas amu 55 (naphthenes) and 57 (paraffins) and the water solublearomatics benzene, toluene, and xylene are more indicative of oil seeps.Also, the 57/55 ratio can be used to determine whether leakinghydrocarbon accumulations contain oil, wet gas, or dry gas.Paraffin/naphthene (57/55) ratios of <0.5 are indicative of biodegradedheavy oils, ratios of 0.5-2.0 are characteristic for normal oils, ratiosof 2 to 4 are typical of wet gas or condensate, and ratios >4 indicatedry gas. The fluorometer supplements the mass spectrometer by detectingaromatic compounds; that locate predominantly oil seeps. Conversely, themass spectrometer complements the fluorometer in that recent organicmatter (e.g., unassociated with thermogenic hydrocarbons) stronglyfluoresces and is a common contaminant detected by the fluorometer.However, no significant hydrocarbon responses may be detected by massspectrometry associated with recent organic matter. Large massspectrometer responses for the non-hydrocarbon gases CO₂, H₂S, or N₂,with or without hydrocarbons, may indicate leaking fluids associatedwith trapped accumulations dominated by these generally non-economicgases that compete for trap space with migrating hydrocarbons. Thesechemical measurements provide the risks for associated non-hydrocarbongases to be assessed in an exploration program.

Accordingly, in one or more embodiments, an unmanned underwater vehiclemay be equipped with sensors to detect and locate hydrocarbons seepingfrom the seafloor into the water column. The location of thermogenichydrocarbon seeps indicate an active hydrocarbon system. Chemicalsensors, which may specifically include a mass spectrometer andfluorometer, may be utilized to distinguish between thermogenic andbiogenic hydrocarbon sources.

As a specific example, the unmanned vehicle may be an AUV. The AUV maysurvey a regional area (e.g., an areas of interest) by collectingsub-bottom profiles, bathymetry, and backscatter along line of travel,and using the data to resolve features less than 1 m across.Simultaneously, the AUV may analyze water chemistry with onboard massspectrometer roughly every 5 seconds for spatial resolution of about 10m. The AUV may also measure acoustic sensitivity relative to surfacevessel acoustics, which may be beneficial in deep water surveys. Then,the chemistry, near-surface geology, and seismic interpretations may becombined, mapped, and integrated into a subsurface model. With thissubsurface model, the measured data may be utilized to track areas ofpotential geologic interest (e.g., faults, stratigraphic pinchouts,fluid escape features), locate active gas/oil seepage vent locations,which may be further sampled for additional direct measurement data.This process may provide information to correlate seeps to subsurfacemigration pathways.

In one or more embodiments, different sensors may be utilized to detectbubbles near and within the body of water. For example, bathymetric oracoustic backscatter expressions may be utilized to detect potentialseeps through the detection of bubbles escaping from the seafloor.Similarly, bubbles related to hydrocarbons from active seeps may bedetected via the seismic or acoustic properties of the bubbles relativeto the surrounding seawater.

In certain embodiments, the acoustic backscatter data may also revealanomalous seafloor reflectivity that can locate carbonate hardgrounds,microbial mats, or black iron sulfides that are consistent withbiological processes where hydrocarbons are consumed or produced atseeps.

In other embodiments, bathymetric expressions may include pockmarks, mudvolcanoes, faults, etc. These measured data may indicate potentialhydrocarbon migration pathways from the subsurface to the seafloor.

In one or more embodiments, the mass spectrometer may be utilized toprovide in situ chemical detection using the membrane-inlet massspectrometer (MIMS). In this system, fluid is passed across a membraneon one side, while a vacuum is drawn on the other side. Hydrocarbons andother gases pass across the membrane into the instrument due to thepressure gradient, where they are ionized and separated by theirmass-to-charge ratio. The MIMS systems may be sensitive to chemicalspecies up to 200 amu in mass; sensitivity is generally better forlighter compounds. See, e.g., (Camilli R C, Duryea A N. 2009.Characterizing Spatial and Temporal Variability of Dissolved Gases inAquatic Environments with in situ Mass Spectrometry. EnvironmentalScience and Technology 43(13):5014-5021.) and SRI (Bell, R. J., R. T.Short, F. H. W. van Amerom, and R. H. Byrne. 2007. Calibration of an insitu membrane inlet mass spectrometer for measurements of dissolvedgases and volatile organics in seawater. Environ. Sci. Technol.41:8123-8128 [doi:10.1021/es070905d]). The methane and higher orderhydrocarbons are detectable down to the ppb level, which may becollected continuously over five second intervals. This interval definesthe spatial resolution of the sensor, which is determined in conjunctionwith the speed of the underwater vehicle. Simultaneous detection ofmultiple species of hydrocarbons is useful in determining whether thesource is thermogenic or biogenic. The limit of detection for thesesystems is listed between 20 nM and 56 nM for methane. These instrumentsanalyze species dissolved in the water and not the composition ofbubbles. It is expected that the concentration of dissolved hydrocarbonsmay be greater near seeps or bubble plumes containing hydrocarbons. Itis also expected that thermogenic hydrocarbons may be distinguishablefrom biogenic hydrocarbons based on the mass spectrum. A C1:(C2+C3)ratio, combined with the proportion of 13C, was linked to the nature ofthe source as described in the reference Sackett W M. 1977. Use ofHydrocarbon Sniffing in Offshore Exploration. Journal of GeochemicalExploration 7:243-254. The MIMS system may enhance the success rate ofany drop core surveys, seismic or other testing in locations wherethermogenic hydrocarbons are detected.

In one or more embodiments, one or more methane sensors may be utilized.Methane sensors are based on conductivity or infrared spectroscopy.Certain methane sensors pass fluid across a supported silicone membraneinto a chamber that contains oxygen and a tin oxide element. When themethane adsorbs onto a layer of tin oxide, it interacts with oxygenpresent in the sensing cavity. This interaction changes the resistancemeasured across the device. The sensor responds slowly and may not reachequilibrium if being towed. However, the concentration above a seep maycause the signal to spike in less than one minute (Lamontagne R A,Rose-Pehrsson S L, Grabowski K E, Knies D L. 2001. Response of METSSensor to Methane Concentrations Found on the Texas-Louisiana Shelf inthe Gulf of Mexico. Naval Research Laboratory reportNRL/MR/6110-01-8584.). As the gas diffuses via Henry's law, thedifference in the partial pressure of methane across the membrane drivesthe influx of methane across the sensor in both directions. The relianceon diffusion slows the equilibrium time of the sensor, which results inless spatial resolution as compared to a mass spectrometer. It may bethat only spikes observed in the data are used as confirmations of seeplocations. As another example, the methane sensor may be based oninfrared (IR) spectroscopy. In this system, a laser is tuned to thenear-IR absorption band specific for methane. The sensor response timeis similar to the methane sensor described above. Other methane sensorsmay utilize a vacuum to pass methane through a membrane. The separationacross the membrane reduces interference from fluid during the analysisand may provide more resolution, but fails to distinguish betweenthermogenic and biogenic sources.

In one or more embodiments, one or more fluorometry sensors may beutilized. These sensors utilize aromatic hydrocarbons that emitfluorescence when excited in the UV (generally due to a π-π* electronicabsorption) with certain regions being significantly “brighter” thanregions that do not contain aromatics. As certain saturated hydrocarbonsdo not emit fluorescent photons when excited with UV light (e.g.,methane, ethane, propane), this sensor is useful for seeps containingbenzene, toluene, and xylene, for example. Though fluorometry providesno specific identification of hydrocarbons present, it may be utilizedwith other sensors to indicate a thermogenic source. As fluorescence isan efficient chemical process, limits of detection can be on the orderof several pM (i.e. 0.004 nM).

Further, the sensors may be utilized to differentiate hydrocarbon seepsbased on a differencing with background values and/or differentiate theseepage levels. That is, the present techniques may reliably distinguishbackground from anomalous hydrocarbon chemistries in water and may alsoprovide a level of seepage from the source. For example, once potentialseeps have been identified in a target location, the autonomousunderwater vehicle carrying appropriate sensors (e.g., massspectrometer, fluorometer, etc.) may distinguish anomalous hydrocarbonamounts from background values and thus reliably detect hydrocarbonseepage. Also, in areas with no seepage, the present techniques mayreduce or eliminate false positives by detection of specific chemicalmarkers. For example detection of ethene and propene may be indicativeof contamination of water from refined and combusted hydrocarbons, ordetection of aromatics from recent organic matter. In areas of lowseepage, the subtle seep characteristics may be reliably detected. Thesesubtle chemical anomalies may rely upon the acquisition parameters, andbackground chemical conditions to differentiate the hydrocarbons fordetection. In this manner, potential seeps that do not yield chemicalanomalies can be eliminated from a list of potential seep locations.This may reduce additional follow-up operations for these areas (e.g.,drop or piston cores, gas and fluid samples), which further enhances theefficiency of the process.

With these detected anomalies, a map or model may be formed on a gridbasis or mapped autonomously through artificial intelligence encodedwithin the underwater vehicle. Mapped anomalies can be used to locatethe seep discharge zone and to relate hydrocarbon leakage to arealgeologic features, such as along fault zones or at stratigraphicpinchouts adjacent to a basin margin. The mapping may also include thegeochemical characteristics of the anomaly to distinguish biogenic fromthermogenic seeps, gas from oil, gas wetness, and oil quality (e.g., theapproximate API gravity).

In one or more embodiments, potential hydrocarbon seeps can be screened(either from ship mounted detectors or from detectors within the AUV)using a combination of multibeam echo sounder (MBES) to detect seabottom topography, texture, and density, while a sub-bottom profiler canlocate shallow subsurface gas anomalies and hydrate layers associatedwith bottom simulating reflectors. We suggest that chemical sensors canbe used to locate anomalous chemistries associated with seeps and seepvents, to map these anomalies relative to geologic features, and todistinguish thermogenic from biogenic gas, and gas from oil.

A two-tiered approach may be utilized where, for example, a 100,000 km²area is screened for hydrocarbon seepage using improved geophysicaltechniques followed by fully-autonomous AUVs equipped with low powerchemical and acoustic sensors. These autonomous AUVs could also beshore-launched or vessel-launched as propulsion and sensor technologiesimprove. It might even be possible to deploy the AUVs from the air.Higher resolution acoustic tools (MBES) for bathymetry imaging, seafloorsurface texture, and bubble detection in the water column are possiblyrequired for screening of seeps in deeper water environments. Once seepscreening is achieved, a coordinated group of low power AUVs equippedwith a mass spectrometer, fluorometer and acoustic (SBP, SSS) sensorswould follow up with missions to detect and map HC anomalies,coordinated with all previous geologic data. This approach could be usedto answer basic questions about active HC systems, acreage selectivity,and play extensions. More specific applications also include locationsof seafloor vents for follow-up sampling for clumped isotope, noble gas,and microbial ecology linkages of seepage zones along the locations ofgeologic features (e.g., faults, stratigraphic pinchouts) to subsurfacemigration pathways, or for use in special environments such as under icein areas with limited seasonal opportunities for surface vessel surveys.This method requires low power AUVs capable of coordinated missionsoperating autonomously with precise positioning capability, immense datalogging/transmission capability, and with the additional challenge ofusing high power acoustic sensors. Given the large areal extent,physical sensors that can survey several thousand square kilometersrelatively quickly appear to have a better chance of success than purelychemical sensors (a technique such as ocean acoustic waveguide remotesensing (OAWRS), for example).

In addition for certain configurations, multiple measurement components(e.g., different hydrocarbon detection sensors) can further enhance themeasurement confidence of the hydrocarbon detection. For example, someof the components (e.g., sensors) may not detect hydrocarbons in certainenvironments. As a specific example, a camera may not detecthydrocarbons if the hydrocarbon droplets are too small and dispersed, asit may indicate other floating debris. However, the camera may easilyidentify microbial mats associated with hydrocarbons that commonlyexhibit large color contrasts with the surrounding seafloor. Similarly,wireless sensors (e.g., acoustic or SONAR sensors) may record signals(e.g., electromagnetic, acoustic or other) that are not generated byseeps, but result from subsea equipment or animals. However, if anacoustic sensor detects certain signals or sounds that indicate ahydrocarbon seep, then a mass spectrometer, methane detector or camera,etc. may be utilized to confirm the leak (e.g., presence ofhydrocarbons). Thus, the use of multiple sensors may reduce thelikelihood of erroneous seep detection.

As a further enhancement, the AUVs may be utilized to expedite thesurvey of a region with potential seep locations. As an example, two ormore AUVs may be deployed by a single vessel within an area to coverdiscrete sections or segments of the area based upon geologic featuresthat may provide migration pathways (e.g., fault traces on the seafloor,interfaces between salt features and surrounding sediments). Bydistributing the AUVs along these potential seep locations, which mayoverlap, the AUVs may be utilized to survey the region in less time thanprevious survey techniques. That is, the region may be divided intovarious sections, based on more favorable areas for seep locations fromgeologic reasoning, for each of the AUVs. As a result, differentsections may be monitored concurrently.

As an example, FIG. 5 is a block diagram of a computer system 500 thatmay be used to perform any of the methods disclosed herein. A centralprocessing unit (CPU) 502 is coupled to system bus 504. The CPU 502 maybe any general-purpose CPU, although other types of architectures of CPU502 (or other components of exemplary system 500) may be used as long asCPU 502 (and other components of system 500) supports the inventiveoperations as described herein. The CPU 502 may execute the variouslogical instructions according to disclosed aspects and methodologies.For example, the CPU 502 may execute machine-level instructions forperforming processing according to aspects and methodologies disclosedherein.

The computer system 500 may also include computer components such as arandom access memory (RAM) 506, which may be SRAM, DRAM, SDRAM, or thelike. The computer system 500 may also include read-only memory (ROM)508, which may be PROM, EPROM, EEPROM, or the like. RAM 506 and ROM 508hold user and system data and programs, as is known in the art. Thecomputer system 500 may also include an input/output (I/O) adapter 510,a communications adapter 522, a user interface adapter 524, and adisplay adapter 518. The I/O adapter 510, the user interface adapter524, and/or communications adapter 522 may, in certain aspects andtechniques, enable a user to interact with computer system 500 to inputinformation.

The I/O adapter 510 preferably connects a storage device(s) 512, such asone or more of hard drive, compact disc (CD) drive, floppy disk drive,tape drive, etc. to computer system 500. The storage device(s) may beused when RAM 506 is insufficient for the memory requirements associatedwith storing data for operations of embodiments of the presenttechniques. The data storage of the computer system 500 may be used forstoring information and/or other data used or generated as disclosedherein. The communications adapter 522 may couple the computer system500 to a network (not shown), which may enable information to be inputto and/or output from system 500 via the network (for example, awide-area network, a local-area network, a wireless network, anycombination of the foregoing). User interface adapter 524 couples userinput devices, such as a keyboard 528, a pointing device 526, and thelike, to computer system 500. The display adapter 518 is driven by theCPU 502 to control, through a display driver 516, the display on adisplay device 520. Information and/or representations of one or more 2Dcanvases and one or more 3D windows may be displayed, according todisclosed aspects and methodologies.

The architecture of system 500 may be varied as desired. For example,any suitable processor-based device may be used, including withoutlimitation personal computers, laptop computers, computer workstations,and multi-processor servers. Moreover, embodiments may be implemented onapplication specific integrated circuits (ASICs) or very large scaleintegrated (VLSI) circuits. In fact, persons of ordinary skill in theart may use any number of suitable structures capable of executinglogical operations according to the embodiments.

In one or more embodiments, the method may be implemented inmachine-readable logic, set of instructions or code that, when executed,performs a method to determine and/or estimate the presence andinformation, such as depth, type, quality, volume and location of thesubsurface hydrocarbon accumulation from a sample related thereto. Thecode may be used or executed with a computing system such as computingsystem 500. The computer system may be utilized to store the set ofinstructions that are utilized to manage the data, the differentmeasurement techniques, the operation of the vehicles and/or the sensoror measurement components, and other aspects of the present techniques.

Other embodiments are described in the following paragraphs:

1. A method for detecting hydrocarbons comprising: performing a remotesensing survey of a survey location; analyzing the remote sensing datafrom the remote sensing survey to determine a target location; deployingan underwater vehicle (UV) into a body of water; navigating the UVwithin the body of water to the target location; obtaining measurementdata within the body of water at the target location; determiningwhether hydrocarbons are present at the target location based on themeasurement data.2. The method of paragraph 1, wherein performing the remote sensingsurvey comprises creating satellite imagery of the survey location.3. The method of any one of paragraphs 1 to 2, wherein performing theremote sensing survey comprises navigating an airborne vehicle to obtainan airborne survey of the survey location.4. The method of any one of paragraphs 1 to 3, wherein remote sensingsurvey comprises performing one or more of ocean acoustic waveguidesurvey; water column seismic survey; active acoustic sensing survey;imagery and spectroscopy of slicks and atmospheric gas plumes; passiveacoustic sensing survey; magnetic and gravity surveys; optical sensingsurvey and thermal anomalies detection survey.5. The method of any one of paragraphs 1 to 4, wherein performing theremote sensing survey comprises imaging the survey location via one ormore of multibeam echosounder and sub-bottom profiler via a marinesurface vessel or underwater vehicle that also includes side-scan sonar.6. The method of any one of paragraphs 1 to 5, further comprisingdetermining the concentration of one or more of thermogenic methane,ethane, propane, butane, other alkanes, aromatics, and non-hydrocarbongases from the measurement data.7. The method of any one of paragraphs 1 to 6, comprising conducting adrop and piston core sampling technique based on the obtainedmeasurement data within the body of water at the target location.8. The method of any one of paragraphs 1 to 7, comprising measuring oneor more of a pH concentration and an oxidation state in the body ofwater.9. The method of any one of paragraphs 1 to 8, comprising measuringmagnetic anomalies via multicomponent magnetometers or gravity anomaliesvia a gravimeter.10. The method of any one of paragraphs 1 to 9, comprising obtainingbiological and chemical sampling of one or more of fluids, gases, andsediments to determine depth, type, quality, volume and location of asubsurface hydrocarbon accumulation from the measurement data.11. The method of any one of paragraphs 1 to 10, comprising measuringmolecular and isotopic signatures of non-hydrocarbon gases andhydrocarbons in the body of water.12. The method of any one of paragraphs 1 to 11, comprising creating oneor more of a chemical map and a physical map of anomalies within thebody of water to locate hydrocarbon seep vents.13. The method of any one of paragraphs 1 to 12, comprising obtaining asample associated with a subsurface hydrocarbon accumulation; anddetermining the noble gas signature of the sample, wherein determiningthe noble gas signature comprises: measuring or modeling an initialconcentration of atmospheric noble gases present in formation water incontact with the subsurface hydrocarbon accumulation; modifying themeasured/modeled initial concentration by accounting for ingrowth ofradiogenic noble gases during residence time of the formation water;measuring concentrations and isotopic ratios of atmospheric noble gasesand radiogenic noble gases present in the sample; comparing the measuredconcentrations and isotopic ratios of the atmospheric noble gases andthe radiogenic noble gases present in the sample to themeasured/modified modeled concentrations of the formation water for aplurality of exchange processes; determining a source of hydrocarbonspresent in the sample; comparing an atmospheric noble gas signaturemeasured in the hydrocarbon phase with the measured/modified modeledconcentration of the atmospheric noble gases in the formation water forthe plurality of exchange processes; and determining at least one of atype of hydrocarbons in the subsurface accumulation, a quality ofhydrocarbons in the subsurface accumulation, a hydrocarbon/water volumeratio in the subsurface accumulation prior to escape to the surface, anda volume of the subsurface accumulation.14. The method of any one of paragraphs 1 to 12, comprising obtaining asample associated with a subsurface hydrocarbon accumulation; anddetermining the clumped isotope signature of the sample whereindetermining the clumped isotope signature of the sample comprises:determining an expected concentration of isotopologues of a hydrocarbonspecies; modeling, using high-level ab initio calculations, an expectedtemperature dependence of isotopologues present in the sample; measuringa clumped isotopic signature of the isotopologues present in the sample;comparing the clumped isotopic signature with the expected concentrationof isotopologues; determining, using said comparison, whetherhydrocarbons present in the sample originate directly from a source rockor whether the hydrocarbons present in the sample have escaped from asubsurface accumulation; determining the current equilibrium storagetemperature of the hydrocarbon species in the subsurface accumulationprior to escape to the surface; and determining a location of thesubsurface accumulation.15. The method of paragraph 14, wherein determining an expectedconcentration of isotopologues includes determining a stochasticdistribution of isotopologues of the hydrocarbon species for a givenbulk isotopic signature for the species.16. The method of any one of paragraphs 1 to 12, obtaining a sampleassociated with a subsurface hydrocarbon accumulation; andcharacterizing the ecology signature of the sample, whereincharacterizing the ecology signature of the sample comprises: using afirst plurality of analyses to determine a community structure of anecology of the sample; using a second plurality of analyses to determinea community function of the ecology of the sample; using the communitystructure and the community function to determine whether the ecology ofthe sample matches a characteristic ecology of a hydrocarbon system; andwhen the ecology of the sample matches the characteristic ecology,identifying the sample as part of a hydrocarbon system associated withthe subsurface hydrocarbon accumulation.

It should be understood that the preceding is merely a detaileddescription of specific embodiments of the invention and that numerouschanges, modifications, and alternatives to the disclosed embodimentscan be made in accordance with the disclosure here without departingfrom the scope of the invention. The preceding description, therefore,is not meant to limit the scope of the invention. Rather, the scope ofthe invention is to be determined only by the appended claims and theirequivalents. It is also contemplated that structures and featuresembodied in the present examples can be altered, rearranged,substituted, deleted, duplicated, combined, or added to each other. Thearticles “the”, “a” and “an” are not necessarily limited to mean onlyone, but rather are inclusive and open ended so as to include,optionally, multiple such elements.

The invention claimed is:
 1. A method for detecting hydrocarbonscomprising: performing a remote sensing survey of a survey location;analyzing the remote sensing data from the remote sensing survey todetermine a target location; deploying an underwater vehicle (UV) into abody of water; navigating the UV within the body of water to the targetlocation; obtaining measurement data within the body of water at thetarget location, wherein measurement components on the underwatervehicle measure molecular and isotopic signatures of non-hydrocarbongases and hydrocarbons in the body of water at the target location andwherein measuring the isotopic signature of hydrocarbons includesmeasuring the signature of clumped isotopologues in a sample from thebody of water; and determining whether hydrocarbons are present at thetarget location based on the measurement data.
 2. The method of claim 1,wherein performing the remote sensing survey comprises creatingsatellite imagery of the survey location.
 3. The method of claim 1,wherein performing the remote sensing survey comprises navigating anairborne vehicle to obtain an airborne survey of the survey location. 4.The method of claim 1, wherein remote sensing survey comprisesperforming one or more of ocean acoustic waveguide survey; water columnseismic survey; active acoustic sensing survey; imagery and spectroscopyof slicks and atmospheric gas plumes; passive acoustic sensing survey;magnetic and gravity surveys; optical sensing survey and thermalanomalies detection survey.
 5. The method of claim 1, wherein performingthe remote sensing survey comprises imaging the survey location via oneor more of multibeam echosounder and sub-bottom profiler via a marinesurface vessel or underwater vehicle that also includes side-scan sonar.6. The method of claim 1, further comprising determining theconcentration of one or more of thermogenic methane, ethane, propane,butane, other alkanes, aromatics, and non-hydrocarbon gases from themeasurement data.
 7. The method of claim 1, comprising conducting a dropand piston core sampling technique based on the obtained measurementdata within the body of water at the target location.
 8. The method ofclaim 1, comprising measuring one or more of a pH concentration and anoxidation state in the body of water.
 9. The method of claim 1,comprising measuring magnetic anomalies via multicomponent magnetometersor gravity anomalies via a gravimeter.
 10. The method of claim 1,comprising obtaining biological and chemical sampling of one or more offluids, gases, and sediments to determine depth, type, quality, volumeand location of a subsurface hydrocarbon accumulation from themeasurement data.
 11. The method of claim 1, comprising creating one ormore of a chemical map and a physical map of anomalies within the bodyof water to locate hydrocarbon seep vents.
 12. The method of claim 1,wherein measuring the isotopic signatures of non-hydrocarbon gases andhydrocarbons includes measuring the signature of isotopologues in asample from the body of water.